Subterranean deposits of natural resources such as gas, water, and crude oil are commonly recovered by drilling wellbores to tap subterranean formations or zones containing such deposits. Various water and/or oil-based fluids, such as water based muds (WBM) or oil based muds (OBM) collectively termed wellbore servicing fluids, are employed in drilling a wellbore and preparing the wellbore and an adjacent subterranean formation for the recovery of material therefrom. For example, a drilling fluid or mud is usually circulated through a wellbore as it is being drilled to cool the bit, control pressure, keep deposits confined to their respective formations during the drilling process, and bring drill cuttings to the surface. The drilling fluid also has the ability to form an impermeable filter cake upon the walls of the wellbore. Other types of wellbore servicing fluids include a fracturing fluid that is used to create fractures in the subterranean formation to thereby increase the recovery of material from the formation. Moreover, a sweeping fluid may be used to flood the subterranean formations, thereby driving oil, gas, or water from the formation into a production wellbore for recovery, and a work-over fluid may be used to perform remedial work in the wellbore.
Drilling through subterranean zones containing clay and shale that swell upon exposure to water requires the use of non-aqueous drilling fluids to avoid problems such as sloughing and well collapse. Such non-aqueous fluids include a base fluid such as diesel oil mineral oil, an olefin, an organic ester, or a synthetic fluid. The drilling fluid may also comprise an invert emulsion, i.e., a water-in-oil emulsion. Unfortunately, fluid loss from such wellbore servicing fluids often occurs in the wellbore, resulting in severe problems. For example, an excessive amount of filter cake may build-up on the walls of the wellbore, causing the drill pipe to become lodged such that it is very difficult to remove it from the wellbore. Further, electrical logging of the wellbore can be adversely affected due to excessively high fluid loss and consequently exacerbates differential sticking.
Wellbore servicing fluids such as drilling fluids often contain additives and conditioning agents that are important in determining the mechanical and physical properties of the fluid. For example, additives are often included that function to inhibit shale and clay disintegration, provide suspension, or improve fluid loss properties. A potential drawback to the inclusion of these additives is their effect on the fluid viscosity. Many additives while providing some improvements in a fluid property adversely affect the fluid viscosity. For instance, an organophilic clay may be included in a wellbore servicing fluid to reduce the settling or stratification of solid particles in the fluid. The addition of such clays may also result in an undesirable increase in fluid viscosity making the fluid more difficult to pump. Thus, a need exists for methods of maintaining a desired fluid viscosity in the presence of commonly used wellbore servicing fluid additives.